1. Field of the Invention
The present invention generally relates to hydraulic fracturing. More particularly, it relates to a downhole tool having a valve for controlling the flow of fracturing fluids.
2. Description of the Related Art Including Information Disclosed Under 37 CFR 1.97 and 1.98
Well completion operations are commonly performed after drilling hydrocarbon-producing wellbores. Part of the completion operation typically involves running a casing assembly into the well. The casing assembly may include multiple joints of casing connected by collars. After the casing is set, perforating and fracturing operations may be performed.
Perforating involves forming openings through the well casing and into the adjacent formation. A sand jet perforator may be used for this purpose. Following perforation, the perforated zone may be hydraulically isolated. Fracturing operations may be performed to increase the size of the initially formed openings in the formation. During fracturing, proppant materials are introduced into enlarged openings in an effort to prevent the openings from closing.
In downhole completion and servicing operations, it may be useful to selectively enable fluid communication between the tubing string and the well bore surrounding the tubing string (i.e., the annulus). It may also be useful for operations such as perforating and fracturing to be performed using a single downhole tool having both capabilities. This avoids the need for multiple trips downhole and uphole, which in turn allows for fluid conservation and time-savings. It may also be useful to carry out operations such as fracturing by pumping treatment fluid down a coiled tubing string. One reason for this is that the coiled tubing string has a smaller cross-sectional area than the wellbore annulus (the annulus being defined as the region between the coiled tubing and the wellbore or, for cased wellbores, the annulus is defined as the annular space between the casing and the coiled tubing). Because of the smaller cross-sectional area of coiled tubing, smaller volumes of fluids (displacement and treatment fluids, for example) may be used.
There exist various circulation valves that allow for fluid to be circulated between different functional components within a single downhole tool. However, many of these valves employ ball-seat arrangements. In ball-seat valves, the ball must be reverse-circulated to the surface after one operation is completed, resulting in a corresponding increase in fluid use and time. Because downhole treatment operations utilize large quantities of fluids, methods or tools that result in fluid savings are desirable.
Various techniques for fracturing that do not require removal of the downhole tool following perforation have been developed. For example, in the SurgiFrac® multistage fracturing technique (Halliburton Company, 10200 Bellaire Blvd., Houston, Tex. 77072), perforating may be carried out by means of a downhole tool having a jet perforation device with nozzles. Perforation may then be followed by pumping a fracturing treatment down the coiled tubing, out of the jet perforation nozzles and into the formation, without the need to remove the downhole tool from the wellbore between perforation and fracturing. Because the diameter of the jet perforation nozzles may be small, a large pressure differential may exist between the interior of the tubing string and the formation, making it challenging to pump treatment fluid at sufficiently high pressure to overcome the pressure differential. Furthermore, proppant is typically used in fracturing. There are often issues associated with moving proppant-laden treatment from the inside of the coiled tubing to the formation. The proppant may become wedged inside the nozzles, preventing its exit into the formation.
Fracturing techniques that rely on the use of fracture valves or fracture sleeves have also been developed. For example, in multi-zone wells, multiple ported collars in combination with sliding sleeve assemblies have been used. The sliding sleeves or valves are installed on the inner diameter of the casing, sometimes being held in place by shear pins. Often the bottom-most sleeve is capable of being opened hydraulically by applying a pressure differential to the sleeve assembly. Fracturing fluid may be pumped into the formation through the open ports in the first zone. A ball may then be dropped. The ball hits the next sleeve up, thereby opening ports for fracturing the second zone.
Other techniques and tools do not require the ball-drop technique. For example, some techniques involve deploying a bottom hole assembly (BHA) with perforating ability and sealing ability. For example, it may be possible to perforate a wellbore using a sand jet perforator, or other perforation device. Following perforation, the wellbore annulus may be sealed using a packer or other sealing means. When fluid is pumped down the coiled tubing, a pressure differential may be created across the sealing means, thereby enabling the fracture valve or sleeve to open, exposing a fracture port. Treatment fluid may then be delivered through the fracture port into the formation. The use of sliding sleeves adds costs to the fracturing operation. Sliding sleeves may reduce the inner diameter of the casing. Also, there may be circumstances where the sleeves do not reliably open, for example, once the environment surrounding the sleeve becomes laden with proppant and other debris.
Therefore, it would be desirable to employ a downhole tool that has both fracturing and perforating capabilities and which allows for fluid savings, time-savings, reproducibility and low-cost manufacture.